In various regions across the United States, “regional transmission operators” (RTOs) or “independent system operators” (ISOs) generally are responsible for obtaining electricity from electricity generators (e.g., operators of coal-fired plants, gas plants, nuclear plants, hydroelectric plants, renewable resources, etc.), and then transmitting the electricity provided by generators over particular geographic regions (e.g., New England, the greater New York area, the mid-Atlantic states) via an electricity transmission infrastructure (also commonly referred to as the electricity “grid”). RTOs generally are responsible for regional planning of grid expansion and/or ordering deployment of new electricity transmission infrastructure by transmission owners.
The Federal Energy Regulation Commission (FERC) presently requires that, in addition to generally managing the operation of the electricity grid in a given geographic area, RTOs/ISOs need to manage the price of electricity generated and consumed on the grid via “wholesale electricity markets.” To this end, RTOs/ISOs establish pricing auctions to provide and support wholesale electricity markets. These pricing auctions, in addition to setting wholesale prices as a function of time, also foster sufficient electricity production for the grid at various locations to ensure that the grid is capable of delivering adequate electricity to respective locations of demand for electricity on the grid. Thus, some of the key objectives of the RTOs/ISOs in overseeing wholesale electricity markets include providing for efficient, economic and reliable operation of the grid.
In general, a given RTO/ISO supports a wholesale electricity market by allowing competing electricity generators to offer their electricity production output to the RTO/ISO. Retail electricity suppliers, also commonly referred to as “utilities,” in turn supply electricity to end-users/consumers, or “energy customers” of the retail electricity suppliers, and are billed by the RTO/ISO for their purchases. With respect to the wholesale electricity market, the retail electricity suppliers make bids for the electricity production output offered by the electricity generators that, once accepted, establish market prices. The retail electricity suppliers in turn typically re-price the electricity they purchase from electricity generators on the wholesale market to sell to their retail electricity customers.
One significant issue facing RTOs/ISOs relates to various limitations that exist in connection with the grid that may impede a sufficient flow of electricity on the grid under certain circumstances. In particular, there may be time-dependent and/or geographically-dependent limitations on the grid's ability to support transmission of electricity, based on one or more of: 1) an available overall supply of electricity from electricity generators; 2) overall demand from retail electricity suppliers; 3) general conditions on the grid itself (e.g., aging, failing or dated equipment); and 4) “location-specific” or “congestion” issues, e.g., respective geographic locations on the grid of electricity generators, electricity consumers, particular demand conditions, and/or particular grid-related conditions that in some manner impede the transmission of available electricity to one or more portions of the grid). In some circumstances, a grid limitation may be caused by a particular branch of the grid reaching a thermal limit, or a failure of a generator or transformer on a branch of the grid; these limitations generally are referred to as “security constraints” (i.e., particular grid infrastructure cannot be overloaded without jeopardizing the grid). As such, the electricity grid is sometimes referred to as a “security constrained system.”
In view of the foregoing, RTOs/ISOs may employ a process known as “security constrained economic dispatch” for establishing wholesale electricity prices on a wholesale electricity market. Pursuant to this process, an RTO/ISO managing a particular geographic region of an electricity grid determines particular locations on the grid, or “nodes,” at which there is a possibility for security constraints to limit electricity transmission. Wholesale electricity prices as a function of time are then established independently for each node (i.e., on a geographically-dependent, or “locational” basis) by accepting bids from energy generators in sequence from the lowest priced offer to the highest priced offer, up to an amount of electricity needed to satisfy electricity demand conditions (e.g., bids from retail electricity suppliers) at the node, so as to develop a supply and demand equilibrium price. In this manner, the wholesale electricity price at a particular node reflects the highest-priced accepted generation offer needed to provide an adequate amount of electricity to that node, taking into consideration various security constraints that may be present at the node. This location-based approach to wholesale electricity prices, which takes into consideration security constraints on the grid, commonly is referred to as “locational marginal pricing,” and the wholesale electricity price at a given node is commonly referred to a Locational Marginal Price (LMP). Thus, the wholesale electricity price generally varies at different locations on the grid, based at least in part on security constraints.
While electricity generators and retail electricity suppliers make up a significant constituency of the participants in wholesale electricity markets, applicable market rules in some wholesale electricity markets also permit electricity consumers/end-users (e.g., energy customers of retail electricity suppliers) and others to participate in wholesale electricity markets so as to earn energy-related revenue and offset their energy-related expenditures. In particular, market rules now permit energy users (or their market representatives) to make offers to curtail or otherwise alter their electricity use, or to sell self-generated or stored electricity, to the wholesale market. If such an offer by an energy customer to provide an “electricity-related product or service” is accepted on the applicable wholesale market, the customer endeavors to appropriately control its various energy assets so as to make available to the grid the offered product/service, in return for payment pursuant to the terms of the offer. The concept of an energy customer providing an electricity-related product or service (e.g., electricity use curtailment) on a wholesale electricity market in exchange for payment to the energy customer by the RTO/ISO, commonly is referred to as “demand response” (DR).
Some of the currently more active wholesale electricity sub-markets in which energy customers of retail service providers may readily participate include the “energy markets” (e.g., “day-ahead” energy market, “real-time dispatched” energy market). While various pricing models exist for participation in these markets and other economic demand response wholesale electricity markets (as well as various penalty models for customer non-performance pursuant to an offer to reduce/curtail energy use), often any revenue generated by the energy customer from participation in these markets is based on the locational marginal price (LMP). The LMP may be calculated periodically at specified nodes (e.g., every 5 minutes, every half-hour, every hour) depending on the particular market in which the energy customer is participating. More generally, revenue generation relating to participation in an economic demand response wholesale electricity market is based on a prevailing “wholesale electricity price” for the particular market in question, which in turn generally is based on the LMP (calculated at various intervals), as discussed above.
To determine revenue earned by participating energy customers in a particular economic demand response wholesale electricity market such as an “energy market,” the amount of electricity use reduction by the participating customer typically has to be measured; subsequently, this measured amount of electricity use reduction typically is multiplied by a price relating to the prevailing wholesale electricity price for the market in question (e.g., LMP). Electricity use reduction by the energy customer conventionally is measured against a reference electricity usage commonly referred to as a “customer baseline” (CBL). The CBL is intended to represent what the participating energy customer's electricity use normally would have been, over a particular time period and typical (“business-as-usual” or BAU) operating conditions for the customer's energy assets, absent the customer's voluntary electricity use reduction based on the incentive provided by the economic demand response wholesale electricity market.
Conventionally, a customer baseline (CBL) electricity use profile for an energy customer is derived by an RTO/ISO from an historical sample of actual electricity use by the customer over a particular time period and BAU operating conditions. In some cases, the particular time period for which an historical sample of the customer's actual electricity use is selected as a CBL may be based, at least in part, on similar conditions prevailing at the customer's site at the time of the historical sampling and participation in the economic demand response program (e.g., similar weather conditions, similar seasons/time of year, similar occupancy conditions at the customer's site, etc.). In other instances, the time period for selecting an historical sample of actual electricity usage as a CBL is based on relatively recent actual electricity use by the energy customer just prior to the customer's participation in the economic demand response program. For example, the ISO PJM Interconnect calculates a market-participating customer's CBL for a given weekday as “the average of the highest four out of the five most recent highest load (electricity use) weekdays in the 45 calendar day period preceding the relevant load reduction event.” In sum, revenue generation from the economic demand response wholesale electricity “energy markets” conventionally is based on an historical actual electricity usage of a participating customer, which historical actual electricity usage serves as a customer baseline (CBL) against which electricity use reduction is measured for purposes of paying the energy customer for the use reduction.